Geothermal: Hotter than ever

02/15/2005 | Ken Wicker

According to the latest available information from the DOE’s Energy Information Administration, non-hydroelectric renewable energy sources produced about 84.2 million kWh in 2003. Geothermal energy, with about 2,800 MW of installed capacity in the U.S., accounts for about 15% of that output—a little more than the sum of wind and solar. To put those numbers in perspective, however, nonhydro renewable generation barely registered on the U.S. generation scale at about 2%. That’s perhaps nothing to write home about—unless you consider the minimal environmental footprint left by these fossil fuel–free facilities.

Historically, geothermal energy use has been about location, location, location. The resource is only tapped in places where hot fluids are relatively close to the surface and easily accessible—generally in active seismic regions. The first geothermal power plant was a dry steam plant, built at Larderello in Tuscany, Italy, in 1904; it is still in operation today (Figure 1). We’ve come a long way in the past 100 years. Today, there are 250 geothermal plants in 22 countries, and they have a total capacity of more than 8,200 MW.

1. Geothermal is a century old. The first commercial geothermal plant was built at Larderello in Tuscany, Italy, in 1904.
Courtesy: U.S. DOE

Going deeper

According to Karl Gawell, executive director of the Geothermal Energy Association (GEA), a Washington-based trade association of U.S. companies involved in the development and production of geothermal power, "The future is bright. Drilling technologies are on the horizon that will allow us to drill deeper than ever before to tap into the deep, hot, dry rock formations of the Earth’s crust."

The ability to drill deeper means that previously unthinkable locations may, in the not-too-distant future, host geothermal power production. Because current technology allows for electricity production at temperatures as low as 195F, deeper wells could turn much of the U.S.—and indeed, the world—into potential resource sites, according to Gawell. "With new mapping and drilling technologies, it is possible to drill as deep as 15,000 feet."

As a matter of fact, they are doing just that down in Australia. Queensland-based Geodynamics Ltd. recently finished drilling 15,000 feet into the hot granite of the Cooper Basin in South Australia to tap into rock as hot as 480F. If the test wells are a success and the company is able to generate steam by pumping fluid down into a heat exchanger far below Earth’s surface, it will be the first power plant of its kind to generate electricity from a closed-loop process, part of which is so far underground.

Meanwhile, in the U.S., geothermal researchers point to a recently published DOE/Southern Methodist University map (Figure 2) that indicates where underground temperatures are high enough to warrant energy extraction. Some of the potential resources are as much as 19,000 feet below the surface. But because deeper drilling now makes those resources recoverable, we could eventually see geothermal power plants popping up like daisies across western states—not just in California, long the capital of U.S. geothermal production with 13,800 GWh of annual output.

2. Digging deeper. New research indicates that the size and scope of U.S. geothermal resources suitable for electricity generation are much larger than once believed. Although most of the best resources are in the western half of the country, technological advances could make drilling deep in virtually every state feasible and rewarding.
Courtesy: U.S. DOE’s Office of Energy Efficiency and Renewable Energy

Fulfilling its potential

Twenty-five years ago, a study by the U.S. Geological Survey (USGS) estimated the potential geothermal generating capacity in nine western states at 22,290 MW. However, Gawell says, "The study is outdated, and nobody can really say what the true potential is until new research is conducted." Researchers at the USGS, realizing that drilling and mapping technologies have advanced tremendously since the 1970s, are in the process of proposing a new, nationwide study. But Gawell isn’t waiting for the results. "We’re certain that the potential exists right now, using today’s technology, to geothermally generate an additional 6,340 MW to 11,700 MW in the U.S."

Legislation is also fueling geothermal advocates’ optimism. With Congress’ recent renewal of the Energy Production Tax Credit (PTC), U.S. geothermal power projects could experience another boom. The new PTC, which won’t expire for another five years, allows an allocation of 1.8 cents/kWh to any facility that generates electricity from geothermal resources. "Now that Congress has acted to support renewable energy, we could see a return to the double-digit annual growth that occurred in the 1980s," Gawell predicts.

It is not only in the U.S. that the industry is feeling bullish. Worldwide, there are 8,402 MW of installed geothermal energy-fueled capacity. According to Gawell, "Production has expanded more than 50% over the past decade, and the potential exists to support 80,000 MW of capacity using current technology—a tenfold increase in today’s level."

As examples of the expansion over the past decade, the GEA highlights Indonesia, which quadrupled its geothermal capacity from 144 MW to 589 MW, and Japan, which nearly tripled its output from 214 MW to 546 MW. Another poster child for geothermal electricity production is the Philippines, which now satisfies 25% of its electricity needs from the resource, thanks to a jump in installed capacity from 891 MW to over 1,900 MW. Four other countries—Australia, Costa Rica, Ethiopia, and Guatemala—also recently joined the ranks of geothermal producers.

How it works

The two most common processes for harnessing geothermal energy to produce electricity involve the use of dry (flash steam) plants and binary-cycle plants.

Dry steam plants use superheated steam at temperatures above 300F that comes directly from the ground. A filter removes any entrained solids from the steam before it enters a steam turbine. As its name implies, the flash steam plant flashes hot, high-pressure water to produce steam in aboveground installed equipment. The steam then turns turbines connected to generators (Figure 3).

A typical flash steam condensing plant has a capacity of anywhere from 5 MW to over 100 MW and requires on the order of 13,000 to 20,000 lb/hr of steam per MW. According to the DOE’s National Renewable Energy Laboratory, electricity produced this way currently costs about 4 to 6 cents/kWh.

Binary-cycle plants (Figure 3), by contrast, use lower-temperature (195F to 300F) hot water. After it is pumped to the surface, the hot geothermal fluid is passed through a heat exchanger through which also runs a secondary (working) fluid—usually a hydrocarbon such as isobutane or isopentane—with a lower boiling point. Some of the secondary fluid vaporizes, turning the turbines and the generators, before it is condensed and returned to the reservoir along with the fluid that remains liquid. Because most new geothermal projects seek to exploit lower-temperature resources, they favor binary-cycle plants, and the choice of most of those plants is an organic Rankine cycle (ORC), for its potentially higher overall cycle efficiency.

Recharging geothermal’s "Old Faithful"

Originally drilled back in the 1920s, The Geysers Geothermal Field in Northern California is a classic geothermal steam facility in that it taps hot vapor deep within bedrock to turn turbine-generators. After decades of constant expansion, The Geysers reached its peak capacity of 1,967 MW in 1987. But since then the site’s effective generating capacity has fallen to 1,100 MW as the reservoir’s steam pressure has fallen from 500 to 200 psi. Nonetheless, because The Geysers still provides 70% of the energy needs of the Northern California coast, the site—the world’s largest geothermal operation—has become the linchpin of a plan to have renewable energy provide 20% of the state’s power needs by 2017.

In the March 2004 issue of POWER, we wrote about a $187 million project to recharge the reservoir beneath the generators at The Geysers. To raise the steam pressure within the reservoir to past levels, engineers built a 41-mile underground pipeline to bring wastewater from a sewage treatment plant to The Geysers, where it is then injected 1 to 2 miles deep. The wastewater boils when it contacts hot reservoir rock and produces a clean "dry" steam for running turbines at all The Geysers’ power plants.

The Northern California Power Authority (NCPA) is one of several owner/operators of the plants at The Geysers. Established in 1968, the NCPA is a nonprofit California Joint Action Agency devoted to the purchase, generation, transmission, pooling, and conservation of electricity for its members. In a similar project, NCPA uses the 26-mile Southeast Geysers Effluent Pipeline from Lake County as a recharge water source.

The NCPA, which owns and operates about 20% of the generating capacity at The Geysers, began developing its facilities at the site in 1977. Since then, the agency has achieved an outstanding record of reliability, logging 22 years of power generation that has produced nearly 30 million MWh. NCPA assets currently consist of 77 geo-thermal wells, two 110-MW power plants (with two 55-MW generating units each), and 7.6 miles of steam pipelines and associated facilities.

4. Steam-powered. Plant No. 2 of the Northern California Power Agency’s Geysers facility has an installed capacity of 110 MW and can generate electricity from the steam field reservoir deep below.
Courtesy: Northern California Power Agency

What’s more, the NCPA is sure that there are vast untapped quantities of heat and steam still below the surface. "We estimate that 399 billion pounds of steam are available for our exploitation through the year 2030," says Grande. Based on current conversion rates, the NCPA forecasts that that steam will fuel the generation of another 24 million MWh of electricity at The Geysers over the next quarter-century.

Desert developer

Another big player in the California geo-thermal energy market is Sparks-based Ormat Nevada Inc. In the past year alone, the company has become the sole owner of the 52-MW Heber plant and the adjacent 48-MW SIGC plant in Imperial County down south, and taken a 50% stake in the 40-MW Mammoth plant in Mono County in the Sierras.

Those acquisitions represent only the latest chapter in a longer-running success story. They follow in the footsteps of Ormat’s purchase in 2002 of the East Mesa geothermal power facility, a few miles east of El Centro in the Imperial Valley. Ormat originally built four of the six power plants that constitute East Mesa’s operations before selling them off to various third parties. But after it realized that the plants were not being run as efficiently as they could have been, Ormat bought them all back in 2002 with plans to overhaul the entire facility.

Since then, the six units have been extensively upgraded, including the replacement of 20 of the 1-MW Ormat Energy Converter units at one of the plants with two 10-MW units that are 25% more efficient (Figure 5). In addition, the company’s engineers decided to reroute several wells to increase efficiency of the overall process. Ormat also has upgraded the injection wells, overhauled one of the turbines, and repaired all the cooling towers. According to Dan Schochet, a company VP, the overhaul increased the output of East Mesa from 42 MW to 50 MW, without drilling any new wells. "This is a shining example of the benefits conveyed by a single, value-added, integrated plant and operations management program," he says.

5. New juice. Two new and more efficient 10-MW binary turbines use the hot fluid from seven production wells at Ormat Nevada Inc.’s East Mesa facility.
Courtesy: Geothermal Resources Council

Recently, Ormat conducted a study with GeothermEx Inc. (Richmond, Calif.) to assess the ability to efficiently recover even more energy reserves at East Mesa, and it indicates a bright future for the facility. According to Schochet, the company thinks it can increase the output of East Mesa by at least 20%.

Land of fire and ice

Húsavík, on Iceland’s north coast, at first glance may appear to be just another settlement in a very remote place. However, the tiny hamlet, with a population of just 2,500 hardy souls, is one of the most energy-efficient towns in the world. Six years ago, city administrators and Orkuveita Húsavíkur (the town’s energy department) decided to tap into the region’s vast geothermal energy potential by developing an innovative municipal energy system (Figure 6).

6. Hot steam in a cold place. The Orkuveita Húsavíkur municipal energy system on the north coast of Iceland uses a 2-MW plant running the Kalina cycle to convert heat from the nearby Hveravellir steam field to electricity.
Courtesy: Arkitektastofan OÖ ehf

Húsavík’s binary plant, which is rated at 2 MW, uses 250F fluids from the nearby Hveravellir geothermal field. However, rather than an ORC, Orkuveita Húsavíkur uses the less well-known Kalina cycle in a pioneering effort in Europe.

According to Henry Mlcak of Recurrent Engineering (Palo Alto, Calif.), the worldwide licensee and developer of Kalina cycle plants, "The primary difference between a typical ORC and the Kalina cycle is the choice of the working fluid. Rather than using isobutane or isopentane, which are far more volatile and less friendly to the environment, we use a mixture of ammonia and water." Although ORC binary cycles have an excellent and extensive track record, "The Kalina cycle has a higher thermodynamic efficiency because it takes advantage of the glide in temperature from the variable boiling and condensing characteristics of the working fluid as it varies in concentration throughout the cycle," explains Mlcak.

Mlcak adds that, in addition to the efficiency it fosters, the ammonia/water fluid has another advantage: its molecular weight is similar to that of water. "This," says Mlcak, "widens the range of turbine technologies we can use, and that in turn increases our ability to reach efficiencies not possible with organic fluid-based cycles." Yet another benefit of the Kalina working fluid is that when the inlet brine temperature turns out to be lower than the plant was designed to handle, the ammonia and water mixture can be easily readjusted to optimize power output at the lower temperature. In addition, the fluid mixture also can be changed on a seasonal basis to optimize plant output for temperature changes in the condenser cooling water—a feat that is not possible with an ORC.

Use every Btu

The operation of the Húsavík power plant is so simple that it runs unmanned. Except for the turbine, the process is no more complex than the one found within most ammonia absorption refrigeration plants. The main components of the plant are:

• A turbo-expander and generator.

• An evaporator with a shell-and-tube exchanger whose tubes are made of low-fin carbon steel.

• A separator composed of stainless steel corrugated profile plates that are assembled with phase-separating chambers.

Since coming on-line in July 2000, the plant has provided 80% of Húsavík’s electricity demand. In addition, the hot water resource is used by local industries to dry hardwood, process shrimp, and produce glucosamine and chitin; and by citizens to heat greenhouses, swimming pools, spas, and barns. Even the cold mountain spring water, warmed in the plant’s condenser, is used—to raise freshwater trout. The ambitious home-grown energy program allows the city and its residents to tap a local resource and avoid having to import fossil fuels.

The Kalina technology also has been proven in a 4-MW waste heat–fueled power plant in Japan that uses 208F hot water as its only energy source. In this plant, the hot water comes from a Sumitomo steel mill near Tokyo.

According to Mlcak, the Húsavík and Sumitomo plants are a conspicuous success, from the point of view of the owners and designers. "Operation over the past four to five years validates the efficiency, environmental friendliness, safety, flexibility, and commercial advantages of the ammonia/water cycle over rival binary cycle technologies," he says.

On the horizon

There’s one more reason the geothermal industry is feeling bullish: The introduction of new technology is in the works in the U.S. Recently, more than a dozen new proposals were received by the DOE’s Geothermal Program in response to its solicitation for cost-shared projects that either seek to improve plant efficiency or allow for electricity generation from lower-temperature geothermal resources. According to Gawell, "DOE staff were impressed both by the number and quality of the responses. There has been a marked increase in industry interest in demonstrating new technology." By the time this issue goes to press, the awards should have been made.

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